1. Field of the Invention
This invention relates to steam turbines and more particularly to apparatus and methods for controlling such turbines as a function of the actual steam conditions in each turbine section.
2. State of the Prior Art
Steam turbines are controlled for the most part by modulating the flow of steam to the turbine through one or generally a group of control valves. Steam flow is controlled to provide appropriate regulation of an end-controlled variable selected for the particular turbine system application. In large electric power generating systems the end-controlled variable is the frequency of the electric power generated which is a function of turbine speed and/or the electrical load carried by the turbine-generator combination.
Under speed control operation a signal developed as a function of the actual speed of the turbine is compared with a reference speed signal and the resultant error signal is utilized in a servo loop to position the control valves to drive the turbine to the desired speed. Speed control is used in ship propulsion systems, boiler feed pump drives, etc., to regulate turbine speed as the end-controlled variable. In electric power generating turbine systems, speed control is normally utilized during start-up and in most instances during shutdown and is also employed to regulate the frequency participation of the individual turbine-generator units in an electric power generating network. The frequency participation of individual turbine-generator units is determined by the proportion of any change in system electrical load assumed by each unit. Due to the presence of substantial inductive loading in commercial electric power networks, any increase in load carried by the system tends to lower the system frequency. Correspondingly, any reduction in load tends to raise system frequency. As the increase in load tends to drive system frequency downward, the speed error produced in the speed control loop will drive the control valves further open to admit more steam, and thus more thermal energy, to the turbine to provide the additional power required to sustain the load at the rated frequency. The gain of the speed control loop determines the percentage of frequency participation of the individual turbine-generator units.
Under load control operation, a reference signal representative of the desired megawatt load to be carried by the turbine-generator unit as determined automatically by an automatic dispatch system or manually by an operator is applied to a turbine control loop. While such a loop may, and in many cases does, include a feedback signal representative of the actual electrical power provided by the generator, the response time of such a loop is very slow, especially in a large electric power generating unit which conventionally includes a high-pressure turbine section, followed by an intermediate pressure turbine and then a low-pressure turbine with a reheater interposed between the high-pressure turbine and the intermediate pressure turbine. It has been determined, however, that when steam is supplied to the turbine system at constant throttle pressure and temperature, the steady state load carried by the turbine-generator unit may be characterized as a direct linear function of the turbine first-stage steam pressure. Thus the final control valve position resulting from a change in desired megawatt load to be carried by the turbine-generator unit can be anticipated by controlling the position of the turbine control valves as a function of an error signal generated as the difference between the megawatt demand signal and a feedback signal proportional to turbine first-stage steam pressure.
The above form of load control functions satisfactorily as long as turbine inlet and exhaust conditions remain constant. However, turbine exhaust conditions are affected by such factors as air leakage, reduced efficiency of the condenser due to fouling of tubes, etc., and variations in condenser circulating water flow and/or temperature. While in the past river or lake water, which remains fairly constant in temperature over prolonged periods, was predominantly used as the condenser coolant (circulating water) and discharged after use, environmental considerations have prompted the recirculation of condenser coolant and the use of cooling towers. Since cooling towers are subject to the larger and shorter term fluctuations of atmospheric conditions, the condenser back pressure on the low-pressure turbines in such an arrangement varies over a wider range and in a shorter period of time than the previous systems. Wet or dry operation of the cooling towers also has significant influence on the efficiency of the cooling towers. The resultant effect is that condenser pressure in a large electric power generating turbine may vary over a relatively wide range. A change in condenser pressure will influence the turbine power even if the turbine first-stage steam pressure remains constant during the transient.
The turbine first-stage steam pressure characterization of turbine power is also premised upon a supply of steam at a predetermined thermal state point, i.e., constant inlet steam conditions. While in many turbine systems the steam generators are capable of supplying steam at substantially constant throttle pressure and temperature over the full operating range of the turbine, in some installations full throttle pressure can not be maintained at full load. There has also been a renewed interest of late in sliding pressure control of steam turbine cycles wherein the turbine control valves remain full open and the pressure of the steam supplied by the steam generator is regulated to control the power developed by the turbine. The advantages and disadvantages of this type of control and of a hybrid system combining constant throttle pressure control over a portion of the turbine operating load range and sliding pressure-control over the remaining portion is discussed in a paper by George J. Silvestri, Jr., Ola J. Aanstad and James T. Ballantyne, entitled "A Review of Sliding Throttle Pressure For Fossil Fueled Steam-Turbine Generators", which was presented at the American Power Conference in Chicago, Ill., Apr. 18-20, 1972.
For units operating with superheated steam and variable inlet pressure over the load range, the turbine control valves are normally used to participate in controlling system steam pressure. In this case, the first-stage pressure alone can not be used as a feedback signal in the control valve positioning loop due to severe interaction with the overall pressure control system. It is necessary in such arrangements to therefore rely on other means for load control.
In the control system described in the above-referenced paper, a throttle pressure characterization of the megawatt demand is employed to control the positioning of the control valves. A signal proportional to the ratio of the first-stage pressure to the throttle pressure is also applied to the control loop as a turbine steam flow feedback signal. However, this control scheme, as well as the other prior art systems, fails to take into account that the state point of the turbine inlet steam is dependent upon temperature as well as pressure and that a change of inlet pressure is accompanied by a change in temperature so that a pressure characterization alone is not an accurate representation of turbine power.
Under speed control operation, variations in turbine inlet and/or exhaust conditions are compensated for by the speed feedback signal. Similarly, in load control operation, a signal representative of the actual electrical power generated by the generator can be fed back into the control loop to compensate for variations in turbine inlet and/or exhaust conditions. In one scheme, a megawatt error signal is integrated and multiplied by the load demand signal to provide multiplication calibration for load error. A serious shortcoming of both the prior art speed control and load control schemes is that they rely upon feedback signals developed at the output of the system and thus are subject to sizable delays in response resulting from the system time constants. In a large multi-element electric power generating turbine unit with a reheater, the time constant may be in the neighborhood of 10 to 15 seconds. These large delays in response time can be compensated for to some extent by the use of feedforward control techniques and by the application of various combinations of control action to the valve position signals. However, these schemes still rely on the first-stage pressure characterization of turbine power which does not account for the variations in turbine inlet and exhaust conditions.
It is also known that turbine inlet and exhaust steam temperatures and pressures can be read and even monitored on a continuing basis, but heretofore these readings have been taken in order to calculate heat rate, turbine efficiency and other performance indicators and have not been utilized to control the operation of the turbine. In this regard, the Liang application cited above teaches methods and apparatus for calculating performance indicators even for turbine systems such as PWR nuclear fueled electric power generating systems in which portions of the turbine systems are operating on wet steam wherein the state point of the steam necessary for making many of the calculations can not be determined by conventional techniques.
In addition to need for control systems which overcome the specific problems discussed above, there is a continual requirement for new generation control systems which provide improved turbine performance in general, such as reduced response time to changes in load or frequency and minimum overshoot during transient.